What changed in this filing

/stocks — the workspaceLOADING

Item 5. Market for Registrant’s Common Equity

2021-04-26 compared with 2020-05-06 · 180 added, 215 removed, 113 unchanged (78% of the section changed)

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mark-up, mark-down or commissions, and may not represent actual transactions.

As of May 5, 2020,

there were 266 registered holders of the common stock.

Provisions of our line of credit agreement restrict our ability to pay dividends.

March 25, 2021, there were 251 registered holders of the common stock.

Provisions of our line of credit agreement restrict our

ability to pay dividends.

Such dividends may be declared out of funds legally available therefore, when and as declared by our Board of Directors.

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We presently own

producing and non-producing properties located primarily in Texas, Oklahoma and West Virginia.

producing and non-producing properties located primarily in Texas, and Oklahoma.

In addition, we own a substantial amount of well servicing equipment.

All our oil and gas properties and interests

are located in the United States.

All our oil and gas properties and interests are located

in the United States.

Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential.

We believe our

balanced portfolio of assets and our ongoing hedging program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities.

We believe our balanced

portfolio of assets and our ongoing hedging program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities.

Our primary sources of liquidity are cash

generated from our operations and our credit facility.

We attempt to assume the position of operator in all acquisitions of producing properties

and will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which we own interests.

We attempt to assume the position of operator in all acquisitions of producing

properties and will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which we own interests.

We continue to actively pursue the acquisition of producing properties.

To diversify and broaden

our asset base, we will consider acquiring the assets or stock in other entities and companies in the oil and gas business.

Our main objective in making any such acquisitions will be to acquire income producing assets to build stockholder value

through consistent growth in our oil and gas reserve base on a cost-efficient basis.

Our cash flows depend on many factors, including the

price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties.

To diversify and

broaden our asset base, we will consider acquiring the assets or stock in other entities and companies in the oil and gas business.

Our main objective in making any such acquisitions will be to acquire income producing assets to build stockholder

value through consistent growth in our oil and gas reserve base on a cost-efficient basis.

Our cash flows depend on many factors,

including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties.

We use derivative instruments to manage our commodity price risk.

This practice may prevent us from receiving

the full advantage of any increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements.

Since all our derivative contracts are

accounted for under mark-to-market accounting, we expect continued volatility in gains and losses on

mark-to-market derivative contracts in our consolidated statement of operations as changes occur in the NYMEX price indices.

On January 30, 2020, the World Health Organization (WHO) announced a global health emergency due to the COVID-19 outbreak, which originated in Wuhan, China, and the risks to the international community as the virus spreads globally beyond its point of origin.

In March 2020, the WHO classified the COVID-19 outbreak as a pandemic, based on the rapid increase in exposure globally.

In addition, in March 2020, members of OPEC failed to agree on production levels which has caused an increased supply and has led to

a substantial decrease in oil prices and an increasingly volatile market.

The oil price war ended with a deal to cut global petroleum output but did not go far enough to offset the impact of COVID-19 on

There has been an increase in supply which has pushed prices down further since March.

If the depressed pricing continues for an extended period it will lead to i) further reductions in the borrowing base under our credit facility which

would require us to make additional borrowing base deficiency payments, ii) reductions in reserves, and iii) additional impairment of proved and unproved oil and gas properties.

We also expect disclosures of supplemental oil and gas information to

be impacted by price declines.

In response to recent commodity prices our efforts to reduce costs include reducing operating costs and

electing to shut-in marginal wells.

The Company will continue to review field operations to minimize costs and identify wells for short term shut-ins through May and

The Company has also implemented a reduction in workforce to further reduce general and administrative costs.

The full impact of the COVID-19 outbreak and the decline in oil prices continues to evolve as

of the date of this report.

As such, it is uncertain as to the full magnitude that these events will have on the Companys financial condition, liquidity, and future results of operations.

Management is actively monitoring the global situation on its financial condition, liquidity, operations, suppliers, industry, and workforce.

Given the daily evolution of the COVID-19 outbreak and the global responses to curb its spread, the Company is not able to estimate the effects of the COVID-19 outbreak

on its results of operations, financial condition, or liquidity for fiscal year 2020.

These matters may have a continued material adverse impact on economic and market conditions and trigger a period of global economic slowdown, which may

impair the Companys asset values, including reserve estimates.

Further, consumer demand has decreased since the spread of the outbreak and new travel restrictions placed by governments in an effort to curtail the spread of the

Although the Company cannot estimate the length or gravity of the impacts of these events at this time, if the pandemic and/or decreased oil prices continue, they may have a material adverse effect on the Companys results of

future operations, financial position, and liquidity in fiscal year 2020.

This practice may prevent us

from receiving the full advantage of any increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements.

Since all our derivative

contracts are accounted for under mark-to-market accounting, we expect continued volatility in gains and losses on mark-to-market derivative contracts in our consolidated statement of operations as changes occur in the NYMEX price indices.

Market Conditions and Commodity Prices:

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economically attractive terms.

Commodity prices are affected by many

factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis

differentials and other factors.

Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels,

basis differentials and other factors.

In addition, our realized prices are further impacted by our derivative and hedging activities.

derive our revenue and cash flow principally from the sale of oil, natural gas and NGLs.

As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil, natural gas and NGLs.

We sell our oil and natural gas on the

open market at prevailing market prices or through forward delivery contracts.

Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing.

We derive our revenue and cash flow principally from the sale of oil, natural gas and NGLs.

As a result, our

revenues are determined, to a large degree, by prevailing prices for crude oil, natural gas and NGLs.

We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts.

Because some of our

operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing.

The market price for oil, natural gas and NGLs is dictated by supply and demand;

consequently, we cannot accurately predict or control the price we may receive for our oil, natural gas and NGLs.

The price of oil and natural gas has fallen

significantly since the beginning of 2020, due in part to failed Organization of Petroleum Exporting Countries (OPEC) negotiations as well as concerns about the COVID-19 pandemic and its impact on

the worldwide economy and global demand for oil and gas.

The resulting precipitous decline in oil and gas pricing experienced during March 2020, through the date of this report, if prolonged.

or a further deterioration of the market price for oil

and natural gas, will negatively impact our cash flows.

consequently, we

cannot accurately predict or control the price we may receive for our oil, natural gas and NGLs.

Index prices for oil,natural gas, and NGLs have improved since the lows of 2020 however we expect prices to remain volatile and consequently cannot

determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or revenues.

Critical Accounting Estimates:

Proved Oil and Gas Reserves

and gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization.

Proved reserves represent estimated quantities of natural gas, crude oil, condensate, and natural gas liquids that geological and

engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made.

The process of estimating quantities of proved oil

and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir.

The data for a given reservoir may also change substantially over time as a

result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.

Consequently, material revisions

(upward or downward) to existing reserve estimates may occur from time to time.

Depreciation, Depletion and Amortization for Oil and Gas Properties

The quantities of estimated proved oil and gas reserves are a significant component of our calculation of depletion expense and

revisions in such estimates may alter the rate of future expense.

Proved Oil and

Proved oil and gas reserves directly impact financial accounting estimates, including depreciation, depletion and

amortization.

Proved reserves represent estimated quantities of natural gas, crude oil, condensate, and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known

reservoirs under economic and operating conditions existing at the time the estimates were made.

The process of estimating quantities of proved oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all

available geological, engineering and economic data for each reservoir.

The data for a given reservoir may also change substantially over time as a result of numerous factors including, but

not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.

Consequently, material

revisions (upward or downward) to existing reserve estimates may occur from time to time.

Depreciation, Depletion and Amortization for Oil and Gas

The quantities of estimated proved oil and gas reserves are a significant component of our calculation of depletion expense

and revisions in such estimates may alter the rate of future expense.

Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease respectively.

Depreciation, depletion and amortization of the cost

of proved oil and gas properties are calculated using the unit-of-production method.

The reserve base used to calculate depletion, depreciation or amortization is the

sum of proved developed reserves and proved undeveloped reserves for leasehold acquisition costs and the cost to acquire proved properties.

The reserve base includes only proved developed reserves for lease and well equipment costs, which include

development costs and successful exploration drilling costs.

Depreciation, depletion and amortization of the

cost of proved oil and gas properties are calculated using the unit-of-production method.

The reserve base used to calculate depletion, depreciation or amortization is

the sum of proved developed reserves and proved undeveloped reserves for leasehold acquisition costs and the cost to acquire proved properties.

The reserve base includes only proved developed reserves for lease and well equipment costs, which

include development costs and successful exploration drilling costs.

Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.

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Our oil and gas production will vary based on actual well performance but may be curtailed due to factors beyond our control.

Our realized oil and gas prices vary due to world political events, supply and demand of

products, product storage levels, and weather patterns.

Our realized oil and gas prices vary due to world political events, supply and demand of products, product storage levels, and weather

We sell the majority of our production at spot market prices.

Accordingly, product price volatility will affect our cash flow from operations.

To mitigate price volatility, we sometimes lock in

prices for some portion of our production through the use of derivatives.

If our exploratory drilling results in significant new

discoveries, we will have to expend additional capital to finance the completion, development, and potential additional opportunities generated by our success.

We believe that, because of the additional reserves resulting from the successful wells

and our record of reserve growth in recent years, we will be able to access sufficient additional capital through bank financing.

Maintaining a strong balance sheet and ample liquidity are key components of our business strategy.

For 2019, we will continue our focus on

preserving financial flexibility and ample liquidity as we manage the risks facing our industry.

Our 2020 capital budget is reflective of commodity prices and has been established based on an expectation of available cash flows, with any cash flow

deficiencies expected to be funded by borrowings under our revolving credit facility.

As we have done historically to preserve or enhance liquidity we may adjust our capital program throughout the year, divest assets, or enter into strategic joint

We are actively in discussions with financial partners for funding to develop our asset base and, if required, pay down our revolving credit facility should our borrowing base become limited due to the deterioration of commodity prices.

The Company maintains a Credit Agreement with a maturity date of February 15, 2021, providing for a credit facility totaling

$300 million, with a borrowing base of $72 million.

As of April 15, 2020, the Company has $53.5 million in outstanding borrowings and $18.5 million in availability under this facility.

The bank reviews the borrowing base

semi-annually and, at their discretion, may decrease or propose an increase to the borrowing base relative to a re-determined estimate of proved oil and gas reserves.

The next borrowing base review is

scheduled for June 2020.

Our oil and gas properties are pledged as collateral for the line of credit and we are subject to certain financial and operational covenants defined in the agreement.

We are currently in compliance with these covenants and

expect to be in compliance over the next twelve months.

If we do not comply with these covenants on a continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest

immediately due and payable.

Our borrowing base may decrease as a result of lower natural gas or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set

forth in our revolving credit agreement.

In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay

any indebtedness in excess of the re-determined borrowing base.

Our credit agreement required us

to hedge a portion of our production as forecasted for the PDP reserves included in our borrowing base review engineering reports.

To mitigate price volatility, we sometimes lock in prices for some portion of our production

through the use of derivatives.

If our exploratory drilling results in significant new discoveries, we will have to expend additional

capital to finance the completion, development, and potential additional opportunities generated by our success.

We believe that, because of the additional reserves resulting from the successful wells and our record of reserve growth in recent

years, we will be able to access sufficient additional capital through bank financing.

Maintaining a strong balance sheet and ample

liquidity are key components of our business strategy.

For 2021, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry.

Our 2021 capital budget is reflective of commodity prices

and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility.

As we have done historically to preserve or enhance liquidity we may

adjust our capital program throughout the year, divest assets, or enter into strategic joint ventures.

We are actively in discussions with financial partners for funding to develop our asset base and, if required, pay down our revolving credit

facility should our borrowing base become limited due to the deterioration of commodity prices.

The Company maintains a Credit Agreement

with a maturity date of February 15, 2023, providing for a credit facility totaling $300 million, with a borrowing base of $40 million.

As of April 15, 2021, the Company has $35.95 million in outstanding borrowings and

$4.05 million in availability under this facility.

The bank reviews the borrowing base semi-annually and, at their discretion, may decrease or propose an increase to the borrowing base relative to a

re-determined estimate of proved oil and gas reserves.

The next borrowing base review is scheduled for July 2021.

Our oil and gas properties are pledged as collateral for the line of credit and we are subject

to certain financial and operational covenants defined in the agreement.

We are currently in compliance with these covenants and expect to be in compliance over the next twelve months.

If we do not comply with these covenants on a continuing basis,

the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable.

Our borrowing base may decrease as a result of lower natural gas or oil prices, operating

difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set forth in our revolving credit agreement.

In the event of a decrease in our borrowing base due to declines in commodity

prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the re-determined borrowing base.

Our credit agreement requires us to hedge a portion of our production as forecasted for the

PDP reserves included in our borrowing base review engineering reports.

Accordingly, the Company has in place the following swap and put agreements for oil and natural gas.

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Put Agreements

Natural Gas (MMBTU)

Oil (barrels)

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The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer side social security payments, net operating loss carryback periods, alternative minimum tax credit

refunds, modifications to the net interest deduction limitations, increased limitations on

qualified charitable contributions, and technical corrections to tax depreciation methods for qualified improvement property.

It also appropriated funds for the SBA Paycheck Protection Program loans that are forgivable in certain situations to promote continued

employment, as well as Economic Injury Disaster Loans to provide liquidity to small businesses harmed by COVID-19.

We have applied for assistance under this program however due to the volume of applications

there is no assurance we will be able to obtain funds under them.

We continue to examine the opportunity that the CARES Act may have to benefit our business.

refunds, modifications to the net interest deduction limitations, increased limitations on qualified charitable contributions, and technical corrections to tax depreciation methods for qualified improvement property.

The Companys activities include development and exploratory drilling.

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come in contact with and drain from a greater volume of reservoir rock over more acreage, with less infrastructure, and thus at a lower cost of development per acre.

We participated in 18 gross (1.6 net) horizontal wells drilled and completed in 2019, all of which were producing at year-end.

In addition, 14 gross (4.63 net) wells that had been completed at year-end 2018 and in which we had participated, were also brought

on-line in 2019.

Of the total 18 wells completed in 2019, three are located in West Texas, while 13 are in our Oklahoma Scoop-Stack horizontal development program.

The three wells drilled in West Texas in 2019

added significantly to our reserve base, as these probable undeveloped locations were the initial test wells in intervals above the Middle Wolfcamp:

one in the Wolfcamp A, one in the Jo Mill and one in the Lower Spraberry, and have

proved up these reservoirs for the 1,300 acre block in which they were drilled.

Our share of the cost of these three wells is approximately $9.2 million.

Not only did these wells add proved developed reserves, but as a result, nine additional

locations in these reservoirs were proven for horizontal development.

Six of the nine horizontals were drilled as of April 15, 2020.

The successful development of these reservoirs has also proved-up

locations to be drilled on our nearby 2,600-acre block in which the Company holds between 14% and 56% interest.

In 2019, we participated in the drilling of three horizontal wells in Upton County, Texas, adding significantly to our proved reserves, as

these probable undeveloped locations were the initial test wells in the Wolfcamp A the Jo Mill and the Lower Spraberry of this acreage.

These tests proved-up these reservoirs for the 1,280 acre

block in which they were drilled and led to the drilling of nine additional wells in 2020 and the first quarter of 2021.

In early 2020,

six of the nine horizontals mentioned above were drilled, and in the first quarter of 2021 the remaining three were drilled.

All nine wells are slated for completion and to be on production by the end of the second quarter of 2021.

average 47.5% interest in these wells and our anticipated total investment is expected to be approximately $27 million.

successful development of these reservoirs has also proved-up locations to be drilled on our nearby 3,260-acre block in which the Company holds between 14% and 56%

It is anticipated that development of as many as 54 additional horizontal wells on this 3,260-acre block will occur over the coming years.

The cost of such development would be approximately $370.6 million with the Companys share being approximately $170.8 million.

The actual number of

wells that will be drilled, the cost, and the timing of drilling will vary based upon many factors, including commodity market conditions.

In early 2020, as mentioned above, the Company participated in the drilling of six wells in Upton County, Texas, operated by Apache

These wells are expected to be completed in the fourth quarter of 2020 with a total anticipated investment of $21 million.

Also in Upton County, Texas, in early 2020, we participated for 7.7% interest in the horizontal drilling of

a well operated by Pioneer Natural Resources that is expected to be completed in the fourth quarter of 2020.

Our total net expenditure for this well is estimated to be $580,400.

Additional drilling and future development plans will be established

based on an expectation of available cash flows from operations and availability of funds under our revolving credit facility.

Exploration, Development and Recent Activities section in Part I above describes in more detail the recent activities of the Company.

The focus of our future activity will be on the continued development of our resources potential in the West

Texas horizontal drilling program as well as our Scoop-Stack horizontal drilling program acreage in Oklahoma in order to maximize cash flow and return on investment.

The Company maintains an acreage position of 19,910 gross (12,560 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton,

Martin and Midland counties and we believe this acreage has significant resource potential in as many as 10 reservoirs, including benches of the Spraberry, Jo Mill, and Wolfcamp that support the potential drilling of as many as 180 additional

horizontal wells.

In Oklahoma, the Companys horizontal activity is primarily focused in Canadian, Grady,

Kingfisher, Garfield, Major, and Garvin counties where we have approximately 3,460 net leasehold acres.

We believe this acreage has significant additional resource potential that could support the drilling of as many as 52 new horizontal wells based

on an estimate of six wells per section:

The cost of such development will be approximately

$370 million with the Companys share being approximately $170 million.

The actual number of wells that will be drilled, the cost, and the timing of drilling will vary based upon many factors, including commodity market conditions.

Also in 2020, in Upton County, Texas, we participated for 8.3% interest in the horizontal drilling of a well operated by Pioneer Natural

Resources that was completed and on production in July of 2020.

Our total net expenditure for this well was approximately $580,000.

Additional drilling and future development plans will be established based on an expectation of available cash flows from operations and

availability of funds under our revolving credit facility.

The Exploration, Development and Recent Activities section in Part I above describes in more

detail the recent activities of the Company.

The focus of our future activity will be on the continued development of our resources potential in the West Texas horizontal drilling program as well as our Scoop-Stack horizontal drilling program

acreage in Oklahoma in order to maximize cash flow and return on investment.

The Company maintains an acreage position of 19,679 gross

(12,461 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin and Midland counties and we believe this acreage has significant resource potential in as many as 10 reservoirs, including benches of the Spraberry, Jo Mill,

and Wolfcamp that support the potential drilling of as many as 180 additional horizontal wells.

In Oklahoma, the Companys

horizontal activity is primarily focused in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 3,460 net leasehold acres.

We believe this acreage has significant additional resource potential that could

support the drilling of as many as 52 new horizontal wells based on an estimate of six wells per section:

three in the Mississippian and three in the Woodford Shale.

Should we choose to participate in future development, our share of the capital expenditures would be approximately $40 million at an average

10% ownership level;

Should we choose to participate in future development, our share of the capital

expenditures would be approximately $40 million at an average 10% ownership level;

the Company will otherwise sell its rights for cash, or cash plus a royalty or working interest.

To supplement cash

flow and finance our drilling program during 2019, the Company sold or farmed-out leasehold rights through several transactions, receiving gross proceeds of approximately $4.28 million in exchange for

444.5 net leasehold acres in Texas and New Mexico.

The majority of our capital spending is discretionary, and the ultimate level of

expenditures will be dependent on our assessment of the oil and gas business environment, the number and quality of oil and gas prospects available, the market for oilfield services, and oil and gas business opportunities in general.

To supplement cash flow and finance our drilling program during 2020, the Company sold or farmed-out

leasehold rights through one transaction in Texas, receiving gross proceeds of approximately $10.8 million in exchange for 1950 net leasehold acres specific to certain depths, reserving rights to shallower and deeper formations for future

The majority of our capital spending is discretionary, and the ultimate level of expenditures will be dependent on our

assessment of the oil and gas business environment, the number and quality of oil and gas prospects available, the market for oilfield services, and oil and gas business opportunities in general.

The Company has in place both a stock repurchase program and a limited partnership interest repurchase program.

Spending under these programs

in 2019 and 2018 was $5.9 and $8 million, respectively.

in 2020 and 2019 was $1,452 thousand and $5.9 million, respectively.

The Company expects continued spending under these programs in 2021.

2019 and 2018 Compared

We reported net income for 2019 of $3.5 million, or $1.72 per share, compared to $14.5 million, or $6.95 per share for 2018.

This decrease was due to increases in oil, NGL and natural gas production and sales offset by lower average prices for all products during 2019 as compared to 2018 offset by gains on the sale of acreage.

The significant components of net income are

discussed below.

Oil, NGL and gas sales decreased $9.2 million, or 9.9% to $84.0 million for the year ended

December 31, 2019 from $93.2 million for the year ended December 31, 2018.

Crude oil, NGL and natural gas sales vary due to changes in volumes of production sold and realized commodity prices.

Our realized prices at the well head

decreased an average of $5.42 per barrel, or 9.0% on crude oil, decreased an average of $11.92 per barrel, or 42.9% on NGL and decreased $0.81 per Mcf, or 35.3% on natural gas during 2019 as compared to 2018.

Our crude oil production increased by 55,000 barrels, or 4.6% to 1,242,000 barrels for the year ended December 31, 2019 from 1,187,000

Results of Operations:

2020 and 2019

We reported a net loss of $2.3 million for 2020, or $1.16 per share, compared to net income of $3.5 million, or

$1.72 per share for 2019.

The current year net loss reflects decreases in production combined with commodity price decreases, increases in gains related to the sale of acreage and changes related to the valuation of derivative instruments.

significant components of income and expense are discussed below.

Oil, NGL and gas sales decreased $47.0 million, or

56% to $37.0 million for the year ended December 31, 2020 from $84.0 million for the year ended December 31, 2019.

Crude oil, NGL and natural gas sales vary due to changes in volumes of production sold and realized commodity

Our realized prices at the well head decreased an average of $17.02 per barrel, or 30.9% on crude oil, decreased an average of $4.65 per barrel, or 29.3% on NGL and decreased $0.25 per Mcf, or 16.60% on natural gas during 2020 as compared to

Our crude oil production decreased by 509,000 barrels, or 41.0% to 733,000 barrels for the year ended December 31, 2020 from

1,242,000 barrels for the year ended December 31, 2019.

Our NGL production increased by 111,000 or 24% to 574,000 for the year ended December 31, 2019 from 463,000 barrels for the year ended December 31, 2018.

Our natural gas production

increased by 662 MMcf, or 17.7% to 4,397 MMcf for the year ended December 31, 2019 from 3,735 MMcf for the year ended December 31, 2018.

The increase in crude oil, NGL and natural gas production volumes are a result our continued drilling

success in the West Texas and Oklahoma regions as we place new wells into production offset by the natural decline of existing properties.

Our NGL production decreased by 137,000 or 23.9% to 437,000 for the year ended December 31, 2020 from 574,000 barrels for the year ended December 31, 2019.

Our natural gas

production decreased by 1,016 MMcf, or 23.1% to 3,381 MMcf for the year ended December 31, 2020 from 4,397 MMcf for the year ended December 31, 2019.

The decreases in crude oil, NGL and natural gas production volumes are a result of the

natural decline of existing properties combined with the shut in of marginal properties due to low commodity prices, slightly offset by new wells placed in production.

The following table summarizes the primary components of production volumes and average

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Twelve months ended

Oil derivatives realized (losses)

Oil derivatives realized gains (losses)

Oil derivatives unrealized gains (losses)

Total gains (losses) on oil derivatives

Natural gas derivatives realized gains (losses)

Natural gas derivatives unrealized gains (losses)

Total gains (losses) on natural gas derivatives

NGL derivatives realized gains (losses)

NGL derivatives unrealized gains (losses)

Total gains (losses) on NGL derivatives

Natural gas derivatives realized gains

Natural gas derivatives unrealized (losses) gains

Total gains on natural gas derivatives

NGL derivatives realized gains

NGL derivatives unrealized losses

Total gains on NGL derivatives

Total gains (losses) on oil, natural gas and NGL derivatives

Prices received for the twelve months ended December 31 2019 and 2018, respectively, including the impact

of derivatives were:

Field service income increased $1.4 million, or 8.4% to

Prices received for the twelve months ended December 31, 2020 and 2019, respectively, including the

impact of derivatives were:

Field service income decreased $8.1 million, or 42.1% to

$11.1 million for the year ended December 31, 2020 from $19.2 million for the year ended December 31, 2019.

Rates on our workover rigs and hot oiler services improved during 2019 and our SWD income increased reflecting increased

utilization of the pipeline and capacity upgrades added in prior years.

Lease operating expenses decreased

This decrease is a combined result of decreased utilization and rates charged to customers as oil and gas prices declined

Workover rig services, hot oil treatments, saltwater hauling and disposal represent the bulk of our field service operations.

Lease operating expenses decreased $10.4 million, or 31.2% to $23.0 million for the year ended December 31, 2020

from $33.5 million for the year ended December 31, 2019.

This decrease is primarily due to the shut-in of high lifting cost properties during 2020 combined with lower production taxes related to

lower commodity prices.

Field service expense decreased $6.4 million, or 41.7% to $9.0 million for the year ended

December 31, 2020 from $15.4 million for the year ended December 31, 2019.

Field service expenses primarily consist of salaries and vehicle operating expenses which have decreased during 2020 related to decreased utilization of our

equipment services.

Depreciation, depletion, amortization and accretion on discounted liabilities decreased

$8.0 million, or 22.1% to $28.2 million for the year ended December 31, 2020 from $36.2 million for the year ended December 31, 2019.

This decrease was due to a reduction of $2.9 million in work-over, marketing,

transportation and production taxes expense off-set by $1.4 million in increased in property taxes and recurring lease operating expenses.

Field service expense increased $0.9 million, or 6.7% to $15.4 million for the year ended December 31, 2019 from

$14.5 million for the year ended December 31, 2018.

Field service expenses primarily consist of salaries and vehicle operating expenses which have increased during 2019 related to increased utilization of our equipment services.

Depreciation, depletion, amortization and accretion on discounted liabilities decreased $1.6 million, or 4.2% to

$36.1 million for the year ended December 31, 2019 from $37.7 million for the year ended December 31, 2018.

The DD&A expense is primarily attributable to our properties in West Texas and Oklahoma, reflecting the declining

cost basis of those properties.

General and administrative expense increased $2.1 million, or 15.4% to

$15.6 million for the year ended December 31, 2019 from $13.5 million for the year ended December 31, 2018.

This increase in 2019 reflects increases in personnel costs combined with lower reimbursements related to sales of

The DD&A expense is primarily attributable to our properties in West Texas and

Oklahoma, reflecting the declining cost basis of those properties.

General and administrative expense decreased

$0.6 million, or 3.91% to $15.0 million for the year ended December 31, 2020 from $15.6 million for the year ended December 31, 2019.

This decrease in 2020 reflects cost reductions put in place responding to sharply lower

commodity prices.

Gain on sale and exchange of assets of $15.8 million for the year ended December 31, 2020 and

$3.7 million for the year ended December 31, 2018 consists of sales of non-producing acreage and oil and gas interests and non-essential field service

Interest expense increased $0.2 million, or 6.5% to $3.6 million for the year ended December 31,

2019 from $3.4 million for the year ended December 31, 2018.

This minor increase relates to an increase in weighted average interest rates throughout the year combined with reduced overall debt for 2019 as compared to 2018.

interest rate paid on outstanding bank borrowings under its revolving credit facility during 2019 and 2018 were 5.34% and 5.33%, respectively.

As of December 31, 2019 and 2018, the total outstanding borrowings under its revolving credit

facility were $53.5 million and $65.5 million, respectively.

Tax expense of $1.4 and $3.0 million was

recorded for the years ended December 31, 2019 and 2018, respectively.

The change in our income tax provision was primarily due to the decrease in pre-tax income for the year ended December 31, 2019

and the change in the deferred income tax assets and liabilities related to Alternative Minimum Tax Credit refunds and Marginal Well Credit carry forwards.

$4.6 million for the year ended December 31, 2019 consists principally of sales of deep rights in undeveloped acreage in West Texas and marginal wells in West Virginia.

Interest expense decreased $1.7 million, or 47.7% to $1.9 million for the year ended December 31, 2020 from

$3.6 million for the year ended December 31, 2019.

This decrease reflects reduced overall debt for 2020 as compared to 2019.

The average interest rate paid on outstanding bank borrowings under its revolving credit facility during 2020 and

2019 were 3.95% and 5.34%, respectively.

As of December 31, 2020 and 2019, the total outstanding borrowings under its revolving credit facility were $37.0 million and $53.5 million, respectively.

Tax expense of $1.4 and tax benefit of $0.5 million were recorded for the years ended December 31, 2019 and 2020,

respectively.

The change in our income tax provision was primarily due to the decrease in pre-tax income for the year ended December 31, 2020 and the change in the deferred income tax assets and

liabilities related to Alternative Minimum Tax Credit refunds during 2020.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

We are a smaller reporting company and therefore no response is required pursuant to this Item.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

The consolidated financial statements and supplementary information included in this Report are described in the Index to Consolidated

Financial Statements at Page F-1 of this Report.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 5. Market for Registrant’s Common Equity